In many industries, such as the production of oil and gas from underground reservoirs, produced fluids flow through thick-walled pipes. It is desirable to be able to characterize such fluids in a non-invasive and rapid manner. One useful characterization of produced fluids is the percentage of water, oil, sand and gas present in a flow stream in a pipe or conduit.
Wells sometimes produce oil, gas, and water simultaneously, in varying quantities. During the later life of oil and gas producing wells, water production typically increases substantially as a percentage of overall produced fluid. Water production in large quantities is undesirable. Water and oil must be separated, and a significant amount of energy is expended on the surface for water/oil separation processes. Furthermore, water takes up pipe volume that otherwise could contain oil or gas, and therefore is an economic detriment in the course of such oil and gas production operations. Produced water must be separated from the hydrocarbons and treated before it is released back into the environment. Water separation and treatment processes are time consuming, costly, and energy intensive.
One manner of investigating and characterization of the oil, gas, and water fraction of a multiphase stream involves acoustics, or sound waves. In a two phase fluid, such as an oil and water composition, sound speed and sound attenuation are related to the composition of the fluid. An “effective” speed of sound may be measured by an acoustic transmission or pulse echo process in a fluid mixture. In such a process, a sound or acoustic pulse of a certain duration may be created by an ultrasonic transducer that is attached to the outer wall of a pipe. The sound may be sent through the fluids in the pipe, and detected on the opposite side of the pipe by a receiving transducer. If the time of the acoustic pulse is determined, then sound speed may be calculated based upon the time and distance traveled, for a given temperature. Once that data is available, then an algorithm may be employed to determine an approximation of the oil and water percentages in the multiphase flow stream.
FIG. 1 shows a conventional prior art system 100 with one emitting and one receiving transducer. In the prior art system 100, an acoustic signal is transmitted from an emitting transducer 102 to a receiving transducer 104 across a fluid 106 that is in a pipe 108. In this prior art system 100, regions 110 represent only about 20% of the cross-sectional volume of the pipe 108 that is interrogated. The remaining 80% of the cross-sectional volume of the pipe 108 presents a region of undetected fluid that is not under examination by the acoustic signal traversing the fluid 106. In the prior art system 100, the accuracy of results obtained is limited by the scope of analysis with respect to the total volume of multiphase flow within the pipe 108.
FIGS. 2 and 3 show results from numerical finite element analysis of the prior art system 100. In FIGS. 2 and 3, areas 202, 302 illustrate that a relatively small amount of the total fluid 200 flowing through the pipe 108 of FIG. 1 is interrogated by the prior art system 100.
There is a continuing need in the industry to improve the accuracy of multiphase fluid characterization. The present disclosure is directed towards improved apparatus, systems, and processes for evaluating and determining the characteristics of multiphase fluid flow in a pipe or conduit. Such characteristics may include the water, sand oil and/or gas percentages in the multiphase fluid flowing through the pipe or conduit.